Many techniques exist in the literature for using magnetic resonance techniques for direct, often real-time, analysis of various properties of liquids transported through pipelines For example, some properties of fluids extracted from a subsurface reservoir can be determined in real time and at in-situ reservoir temperatures and pressures based on the measurement of the fluid's transverse (T2) and longitudinal (T1) relaxation times, and as well as their self-diffusivity (D). The parameters derived from such measurements include, e.g., the relative fractions of hydrocarbons and water that have contributed to the measured NMR signal, the level of contamination of the hydrocarbon fluid phase by infiltrations of water or drilling mud, and estimations of hydrocarbon viscosity.
These measurements can be realized both as surface and subsurface experiments and often reduce ambiguities associated with samples extraction and sample transport. Some analytical methods based on Magnetic Resonance and its associated devices are described, for example, in the U.S. Pat. No. 6,111,408, “Nuclear Magnetic Resonance Sensing Apparatus and for Techniques down hole Measurements;” U.S. Pat. No. 6,737,864 B2, “Magnetic Resonance Fluid Analysis and Method;” U.S. Pat. No. 6,825,657 B2, “Magnetic Resonance for Method Characterizing Fluid Samples Withdrawn from Subsurface Earth Formations;” U.S. Pat. No. 6,891,369 B2, “Magnetic Resonance Method and Logging for Apparatus Fluid Analysis;” U.S. 2005/0040822 A1, “Multi-measurements NMR Analysis based on Maximum Entropy;” U.S. 2006/0122779 A1, “Interpretation for Methods NMR Diffussion-T2 Maps;” U.S. Pat. No. 7,872,474, “Magnetic Resonance Based Apparatus and Method to Analyze and to Measure the Bi-Directional Flow Regime in a Transport or a Production Conduit of Complex Fluids, in Real Time and Real Flow-Rate,” U.S. Pat. No. 7,719,267, “Apparatus and Method for Real Time and Real Flow-Rates Measurements of Oil and Water Cuts from Oil Production,” and the references contained therein.
In U.S. Pat. No. 4,785,245, magnetic resonance is used to determine the relative fractions of petroleum and water and the flow velocity in a fluid conduit. The determination of petroleum and water fractions is generally carried out by means of the magnetic resonance signal that is weighted by the individual spin-lattice relaxation times (T1) of either fluid component. This technique requires that the individual transverse relaxation time of the water phase in the hydrocarbon/water mixtures differs from that of the oil phase. For most applications, this requirement is sufficiently fulfilled. In addition, for hydrocarbon mixtures comprised of low- and high viscosity components it is also often possible to measure the ratio of the light- and heavy components as long as their respective values of longitudinal relaxation times is sufficiently different to isolate the corresponding magnetic resonance signals.
For the measurement of flow-rates two basic principles can be identified.
The determination of the fluid flow-rate through the measurement of “flight time” of fluids between two magnetic resonance spectrometers: (or between two sensors of a single spectrometer). See, for example, U.S. Pat. No. 6,046,587 “Measurements of Flow Fractions, Flow Velocities and Flow Rates of a Multiphase Fluid using NMR Sensing,” or U.S. Pat. No. 6,268,727 “Measurements of Flow Fractions, Flow Velocities and Flow Rates of a Multiphase Fluid using ESR Sensing.” Both patents disclose a sensor that uses at least two magnetic resonance spectrometers or one magnetic resonance and another electron paramagnetic resonance spectrometer. The basic principle of this approach is based on what is known as the “flight or passage time” of magnetic resonance-excited fluid nuclei between both spectrometers. Another variant of this method is US patent application 2004/001532, “Method and procedure to measure fluid flow and fluid fraction, and equipment used to that end.” In this case there is only one electronic part, shared by two sensor coils. The operation principle of the approach described in the '532 reference is the same as outlined in the '727 reference, namely, the flow velocity of water and hydrocarbon molecules is separately measured via the respective time required for each component to straddle the space between the two sensor coils. While theoretically correct, this “time-of-flight” approach has little practical feasibility for oil-field applications, as it is limited to relatively slow flow velocities and is expensive to implement.
Another method for measuring fluid flow by means of magnetic resonance is based on the spatial encoding of the flow velocity by means of a magnetic field gradient that is oriented in the direction of the flow. This approach employs magnetic field gradients (static and/or electronically pulsed) to modulate the precession phase of protons spins. A flow meter with fluid phase separation that uses pulsed electromagnetic field gradients is disclosed, for instance, in U.S. Pat. No. 6,452,390, “Magnetic Resonance Analyzing Flow Meter and Flow Measuring Method.” This method has the disadvantage that the maximum flow velocities detectable are proportional to the intensity of the applied field gradient pulses. Therefore, the measurement of realistic flow velocities as encountered during hydrocarbon production and transport requires magnetic field gradients of high intensity, which also need to be switched on and off during extremely short time periods. Such gradient pulses are difficult to achieve, in particular across sensed volumes that are comparable to the cross-section of conduits typical used in oil-field applications. Consequently, this methodology is generally restricted to measurements of relatively low flow rates.
A version of this method that includes applying a permanent longitudinal gradient field is described in US patent application US 2006/0020403, “Device and Method for real time direct measurement of the Flow-Rate of a Multi-Component Complex Fluid.” The '403 reference discloses a flow meter and the measurement of fluid fractions in multiphase flow by one coil associated to a magnet of slightly oblique flat polar faces. The device generates a magnetic field gradient in the direction of fluid flow, in addition to the constant magnetic field required to detect the magnetic resonance signal. The spatial encoding of the temporal position of the resonant nuclei is realized by means of the linear magnetic field gradient in the volume that is probed by the excitation- and detection magnetic resonance coil. For high flow speeds, this gradient must be increased to achieve the corresponding encoding of the protons that compose the circulating complex fluid. While larger permanent magnetic field gradients can, in principle, be realized using different magnet shapes, this measurement approach reaches its limit because the increase in magnetic field gradient intensity is accompanied by a corresponding increase in the frequency content of the detected magnetic resonance signal. For a given bandwidth (of the electronics used for transmitting and receiving the radio-frequency signals), this broadening of the magnetic resonance line width—as represented in the frequency domain after the time-domain signal has been Fourier-transformed—causes the signal-to-noise ratio of the detected signal to deteriorate. This, in turn, causes a reduction in measurement precision and increases the time required for an individual measurement. Furthermore, it is possible that the detected NMR signal originates only from fluids located within a thin slice oriented perpendicular to the direction of the magnetic field gradient rather than from all fluids in the pipe.
The foregoing principles are advanced further in U.S. Pat. Nos. 8,143,887 and 8,212,557, the disclosures of which also include an exemplary system and methods for making NMR measurements of multiphase flow.
Except to the extent they contain statements that contradict statements made in the present application, all of the references mentioned herein are incorporated herein in their entireties.
The approaches outlined above are limited to the measurement of the average flow-rates of the fluid components. It has been discovered, however, that because these methods rely on a quantifiable diffusion contrast between the liquid and gas phases, they do not always give accurate results at low gas pressures or low gas velocities. Thus it remains desirable to provide a method and apparatus that can more precisely assess the velocity profile of each individual component of a multiphase fluid without using time-of-flight measurements.